The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
In the production of hydrocarbons from wells in subterranean formations, the formations are often stimulated to facilitate increased production of hydrocarbons. One method of stimulation is to hydraulically fracture the formation by introducing a fluid, known as a fracturing fluid or “frac fluid,” into the formation through a wellbore and against the surface of the formation at a pressure sufficient to create a fracture or further open existing fractures in the formation. Usually a “pad fluid” is first injected to create the fracture and then a fracturing fluid, often bearing granular propping agents, is injected at a pressure and rate sufficient to extend the fracture from the wellbore deeper into the formation. If a proppant is employed, the goal is generally to create a proppant filled zone (aka, the proppant pack) from the tip of the fracture back to the wellbore. In any event, the hydraulically induced fracture is more permeable than the formation and it acts as a pathway or conduit for the hydrocarbon fluids in the formation to flow to the wellbore and then to the surface where they are collected. These methods of fracturing are well known and they may be varied to meet the user's needs, but most follow this general procedure.
The fluids used as fracturing fluids in such formations are typically fluids that have been “viscosified” or thickened, which facilitates fracturing and proppant transport. Viscosification of the fluid may be achieved through the addition of natural or synthetic polymers (cross-linked or uncross-linked). The carrier fluid is usually water or a brine that is viscosified with the viscosifying polymer, such as a solvatable (or hydratable) polysaccharide. The fluids used for hydraulic fracturing may also be viscosified or thickened with viscoelastic surfactants. These are non-polymer fluids that are typically formed from surfactants that are either cationic, anionic, zwitterionic, amphoteric or nonionic or employ a combination of such surfactants. In either case, such fracturing fluids are relatively costly due to the expense of the various components and additives used.
Additionally, while the use of such hydraulic fracturing fluids typically improves the overall permeability of the formation by establishing a high-permeability path between the newly-exposed formation and the wellbore, amounts of the viscosified fluids can leak off into the formation and may reduce the relative permeability in the invaded region after the treatment. Cleanup of these fluids is therefore an important consideration, which may add to the cost of treatment. And even with effective cleanup, there is always the potential that some damage will remain.
In some formations, particularly near the fracture, the permeability to gas in some portions of the formation may be close to zero. Such low-permeability formations are often referred to as “tight”. The recovery of methane gas from tight subterranean formations has been a particular problem, especially in shales, such as Texas' Barnett Shale. In such formations, fracturing with conventional viscosified fracturing fluids may not be practical due to the expense and risk of damage to the already low permeability of the formation.
One method of stimulating tight shale or sand formations is through water or “slick-water” fracturing. In such fracturing operations, water, which may be combined with a friction reducing agent in the case of slickwater, is introduced into the formation at a high rate to facilitate fracturing the formation. These fracturing fluids may produce longer, although more narrow fractures, and also use lighter weight and significantly lower amounts of proppant than conventional viscosified fracturing fluids. These water fracturing fluids are particularly useful in low-permeable, gas-bearing formations, such as tight-gas shale and sand formations, where fracture width is of less concern. The water or slick-water fracturing fluids may be brine or fresh water, depending upon the properties of the formation being treated. The water fracturing fluids also require less cleanup than conventional viscosified fracturing fluids.
While slickwater fracturing fluids may require less cleanup than conventional viscosified fluids, there is still the possibility of fracture or formation damage from the friction-reducing polymer. Typically, polyacrylamides are used as the friction-reducing polymer. These polymers are synthetic polymers and there is a general perception in the industry that the polyacrylamides are difficult to break to facilitate cleanup.
Accordingly, new and improved slickwater fracturing fluids and methods for breaking the friction reducing polymers used in these fluids to minimize fracture and formation damage are needed.